Analysis of fluid samples associated with wellbores penetrating earth formations for hydrocarbon recovery may comprise collecting and analyzing samples from the wellbore or from an earth formation(s) surrounding the wellbore. In addition, it is often necessary to analyse and evaluate hydrocarbon mixtures flowing from such wellbores in pipelines and the like and hydrocarbon mixtures found in and around such wellbores during well servicing and the like. For example, the analysis of fluid samples from a hydrocarbon well for the determination of phase behaviour and chemical composition may be an important step in the evaluation of the producibility and economic value of the hydrocarbon reserves in the earth formation. An important factor in determining the economic value of gas and liquid hydrocarbon reserves is their chemical composition, particularly the concentration of gaseous components, such as hydrogen sulphide, carbon dioxide, hydrogen, sulphide and lighter hydrocarbons (such as propane, ethane, methane or the like). Additionally, corrosion of transportation pipelines and analysis of well servicing actions are also important in the development and production of hydrocarbons from the wellbore. Therefore, real time gas detection is an important process for downhole fluid analysis, hydrocarbon transportation and well servicing.
Contrary to surface analysis, various available approaches—optical, chromatography, etc—to detect gaseous components—such as hydrogen sulphide, carbon dioxide, hydrogen, mercapto gases and methane—present in downhole environments have been difficult to commoditize due to limitations such as the downhole operating environment, which may involve high temperatures and/or pressures, size of the downhole tools for making such measurements and the presence of water and/or other fluids.
In the case of hydrogen sulphide (“H2S”), its presence in fluids found in the permeable formations of oil wells has an important impact on the economic value of the produced hydrocarbons and production operations. Typically, the sulfur content of crude oils is in the range 0.3-0.8 weight percent and the H2S content of natural gas is in the range 0.01-0.4 weight percent, although concentrations of H2S in natural gas of up to 30 weight percent have been reported. Several reports have claimed a systematic increase in the sulphur content of crude oils over the past 10-20 years and anticipate further significant increases in the concentration of H2S in both oil and natural gas.
Together with carbon dioxide (“CO2”), the presence of H2S in downhole fluids may give rise to safety and logistical problems. For example, the leading causes of mechanical failure of materials in the oil and gas industry are estimated as follows: CO2 corrosion (28%), H2S stress cracking (18%), welding (18%), pitting (15%), erosion (12%), galvanic (6%) and stress (3%). As such, for downhole tools, equipment or the like, corrosion caused by gaseous elements and associated problems may be reduced/managed by measuring/detecting such gaseous components.
However, surface measurement/detection of such gas components is problematic because, among other things, transporting the sample to the surface for analysis is inefficient as it is time consuming, and as a result costly, and the transportation process may affect accurate measurement/detection due to the change in environment. With regard to H2S, a problem associated with sampling fluids containing H2S is partial loss of the H2S due to reaction of the H2S with metal components, particularly those made from iron-based metals. H2S readily forms non-volatile and insoluble metal sulphides by reaction with many metals and metal oxides, and this prevents accurate analysis of H2S in a fluid sample transported to the surface in a metallic tool. Since fluid samples are usually collected in metal containers, which are able to maintain the pressures at which the samples were collected, a problem associated with sampling fluids containing H2S is partial loss of the gas by reaction of the H2S with the metal components, particularly those made from iron-based metals. After contact of the H2S with metal components during transport, any measurements performed at the surface may give an underestimation of the true H2S content.
With regard to downhole detection and/or measurement of gaseous components of downhole fluids various problems exist. For example, it may be difficult to determine properties of the gaseous components directly from the fluid sample. Additionally, the high temperatures and pressures in the wellbore may make use of chemical reactions or the like problematic.